Crude oil derived from bitumen associated with “oil sands” now accounts for a significant portion of the world's energy. Where deposits are located at or near the surface it is possible to employ mining techniques to move oil sands to a processor where the bitumen is separated from the sand. In situ production methods are used when deposits are buried too deep to be mined economically. Several techniques are known for decreasing the viscosity of the bitumen to facilitate in situ production, including steam injection, solvent injection and firefloods. Steam injection techniques include steam assisted gravity drain (SAGD), mixed well SAGD (Row of vertical wells used as steam injectors instead of horizontal steam injectors, FIG. 1), steam flooding (FIG. 2), and cyclic steam simulation (FIG. 3).
The basic principles of in situ production by separating bitumen from sands with heat can be illustrated by SAGD. Steam is introduced to the deposit via one or more steam injection wells. The injected steam increases the temperature of the deposits surrounding the well, thereby decreasing the viscosity of the bitumen. In other words, heating melts the semi-solid bitumen, which allows it to separate from the sand. The separated bitumen flows downward in the reservoir due to the force of gravity and is captured by a production well. The captured bitumen is then pumped to the surface and mixed with liquids obtained from natural gas production (condensate) in preparation for transport and processing.
One problem associated with each of the techniques is direct production of an introduced element, e.g., steam. Even in a relatively homogenous deposit, pathways of lower hydraulic resistance may form, resulting in non-uniform steam penetration. If a pathway reaches the production tubing then steam may enter the production well. This is undesirable because it tends to decrease efficiency, damage equipment and contaminate the product.
It is known to throttle production wells in order to maintain production temperature below injected steam temperature, and thereby prevent direct production of steam. For example, it is known to maintain a temperature balance in SAGD applications with sensors and chokes. However, the relatively high reservoir temperatures associated with steam injection, e.g., 650° F., are too great for many control system components. Consequently, components are typically positioned well away from the wells. This is problematic, but is tends to compromise the accuracy and reliability of control. The situation is exacerbated by extended horizontal sections over which significant temperature variation may be present.